Natural gas gathering compressor facilities built using traditional methods use separate pieces of equipment connected with lengths of pipe which must all be sized for anticipated station growth. The growth plans change often, affected by the dynamic nature of drilling plans, differing well production flows, and unknown longevity/decrease of flows from different wells. Using an optimistic approach a station will be built with oversized pipe and equipment anticipating a target growth size. Until that size is reached, the extra cost of the larger initial infrastructure burdens the economics for the site. If a station outgrows its target size, then the current infrastructure must be re-built to handle the added site capacity—an expensive and often fatal economic blow to the expansion plans.
Traditional compressor facility designs are progressing into a mode where equipment modularization is perceived as a cost saving design and construction advantage. Previous modularization efforts, however, simply mimic the usual approach of using separate pieces of equipment connected with separate utility and process piping systems. This usually results in a large site with extensive site civil works, with lengthy and expensive construction schedules.
A compressor station is a facility which helps the transportation process of natural gas from one location to another. A gathering compressor station is used as a centralized location where several wells in an area send their flows. Though natural gas is considered “dry” as it passes through a pipeline, the raw gas from the wells is saturated with liquids in the form of hydrocarbons or water. This liquid condenses in the pipes leading to the compressor station and eventually flows into the station from planned pigging operations or as unplanned slugs of free liquids. Compressor stations typically include equipment such as slug catcher vessels, scrubbers, strainers or filter separators which remove liquids, dirt, particles, and other impurities from the natural gas. These removed impurities from the gas are disposed as waste or sold if possible. There are roughly five major parts of a station design. These are generally broken into the following categories: Inlet Systems; Compression; Discharge Systems; Dehydration; and Utilities.
Previous Inlet Slug Catcher systems work by routing all of the incoming gas and liquid through a large steel vessel where the gas slows down enough for any liquids to fall to the bottom of the vessel. Additional mechanical methods such as demisters or vane packs are sometimes employed in the vessels to assist with liquid separation. Since the vessel size is limited by shipping dimensions (and weight), additional liquid storage space is often added; these storage spaces are commonly referred to as “finger skids”. From the temporary storage in the vessel and finger skids, the liquid is slowly drained into liquid pipes, known as liquid “headers”; that run throughout the facility. These pipe systems carry the gathered liquids to on-site storage tanks or processing systems. The liquid-free gas is then routed to the compressor suction via piping, systems known as gas “headers”.
The inlet to a compressor station must be designed to the possible future size of the facility since it is generally intended to be a gas receipt point from multiple wells over a number of years. This process is always filled with compromise since the general industry mindset is to “build it once”, but with increasing size comes higher initial cost. Sizing the inlet system is usually a problematic issue. When sizing a gathering facility's inlet system, the Engineer needs to evaluate possible gas pressures and flow rates that could occur over time. The evaluation starts with identifying the possible mix of liquids and gases that comes up from a gas well. Usually the Producer (well owner) installs a steel vessel at the well location to separate the free liquid from the gas. If this equipment malfunctions or is not properly operated, some or all of these free liquids can be sent with the gas to the compressor station. Even when well pad separation equipment is properly operated, the gas leaving the well, pad is still saturated with liquids (analogous to a “fog”). The gas cools as it runs through underground piping to a compressor facility. When the “fog” cools it condenses, or “rains”, inside the pipe. To keep the pipe from filling with condensate over time, the pipeline Operators will run a “pig” (analogous to a rubber “squeegee”) through the line to push the liquids out of the pipe. This liquid ends up coming into the compressor station as a “slug” of liquid. Depending on the gas composition, frequency of the pigging, terrain “ups mid downs”, the amount of gas flowing through the line, distance from the wells, and ambient conditions, the liquid volumes can vary. There are always unknown variables that can affect the amount of liquids coming into a station. One of the biggest unknowns is how much gas will end up flowing to the proposed station since higher gas flows carry more saturated liquids which in turn increase the condensate volumes. All of these factors make the “one-time” initial sizing of compressor station inlet separation (Slug Catcher) equipment a frustrating challenge.
The second part of an inlet system is an inlet filter separator vessel. This piece of equipment is installed downstream of the Slug Catcher as a secondary system to prevent any liquid that may get past the Slug Catcher from making its way to the compressors. This unit generally has two internal sections, one for trapping free liquids, and a second filter element section used to trap any airborne particulates. In the traditional vessel design, each of these two internal systems drain into separate sump partitions within the vessel and then on through a set of redundant automated drain systems to a facility liquid drain pipe.
After traversing the inlet system, liquid-free gas then goes through a series of piping systems to the compressors. All of these main artery lines throughout the facility are sized for a maximum flow at a given pressure. As previously mentioned, this sizing for future flow conditions is part educated guesswork tempered with an analysis balancing costs with the risk of under or oversizing the infrastructure. Once the gas lines reach the compressors, a branch line is routed to each machine. Each compressor size requires more or less flow, and the piping systems to and from each machine must be sized to the specific operating conditions for each machine.
Each compressor generates liquid through normal operation of cooling the compressed gas. Additional liquid sources from the packaged compressor include drain systems on the compressor skid, oil changes, etc. This liquid from each individual packaged compressor is generally routed to a main liquid drain pipe line that is run along the spaced compressor installations. In many facilities, there are two main liquid drain pipe lines. One line is dedicated to high pressure drain liquids and the other to low pressure drain liquids. In many designs, these lines are both routed separately to on-site storage tanks for disposal or further processing needs.
When a reciprocating compressor (piston units “smashing” the gas) compresses gas, oil is injected to keep the pistons lubricated. Some of this oil ends up in the gas as it leaves the compressor. It needs to be removed. The discharge gas from each compressor is traditionally run to a station-sized common discharge pipe “header”. This compressor discharge gas piping is routed along the same stretched out multi-compressor arrangement and the discharge gas from each machine is sent to this common pipe. To remove the oil from the discharge gas, another filter separator vessel is installed. The common discharge pipe header routes the combined discharge gas from many compressors to a common discharge oil separator vessel. This filter vessel generally has the same functional features as the inlet filter separator vessel. The traditional two stage vessel design uses the same drain system arrangement with one drain from the pre-filter portion of the internals, and a second from the post-filter element section of the vessel internals. Each of these drain connections are traditionally directly routed to dedicated sumps included as part of the traditional vessel design. Each of the traditional two sumps provided with the vessel supply has a drain connection that is connected through a plurality of pipes to the main facility drain, pipe(s) routed to the vessel area. Each of the drain systems directly connected to the vessel uses manual isolation valves, strainers, backflow prevention valves, bypass valves, and automated valves which are controlled by instrumentation systems on the vessel that monitor level in each sump area. Because of known frequent failures/malfunctions with the automated drain systems, traditional installations use redundant drain systems at each drain connection. As with the inlet filter separator vessel, it is difficult to size the discharge oil separator since sizing of the vessels involves some assumptions for the maximum required size (for a fully-grown station) or it involves leaving provisions for future parallel installations which require-extra costs both during the initial station build and again when equipment is added.
In some facilities, a dehydration system is installed to remove saturated water content from the gas. This process is generally performed by forcing the gas through a vertical vessel called the dehydration contactor tower where the gas is brought into “contact” with liquid glycol pumped through the tower. Any saturated water in the gas has an affinity for the glycol and the gas is dehydrated (water removed) in the dehydration contactor tower. Since some liquid glycol droplets may be carried through the dehydration contactor tower with the exiting gas, a glycol filter separator vessel is typically installed downstream of the dehydration contactor tower. Similarly the previously described inlet filter and discharge oil separator vessels, the glycol filter separator vessel is usually a traditional two stage vessel design that uses the dual drain system arrangement with one drain from the pre-filter portion of the internals, and a second from the post-filter element section of the vessel internals. Each of these drain connections are traditionally directly routed to dedicated sumps included as part of the traditional vessel design. Each of the traditional two sumps provided with the vessel supply has a drain connection that is connected through a plurality of pipes to the main facility drain pipe(s) routed to the vessel area. Each of the drain systems directly connected to the vessel uses manual isolation valves, strainers, backflow prevention valves, bypass valves, and automated valves which are controlled by instrumentation systems on the vessel that monitor level in each sump area. Because of known frequent failures/malfunctions with the automated drain systems, traditional installations use redundant drain systems at each drain connection.
All of the previously described systems are typically designed to perform their functions for the entire compressor facility where there are multiple compressors. This leads to several common problems. For example, the inlet system must be designed to feed several compressors. However, due to the changing nature of natural gas drilling and production, it is unusual that all the compressors planned for any site are needed and installed with the initial facility build. Therefore, the installed size (or capacity) of an inlet system rarely matches the installed compression needs at any given site. Oversizing the infrastructure for planned expansion results in extra costs for the initial station build. The penalty for under-sizing the same infrastructure could be that future expansion needs are prohibitively expensive.
Previous practices for handling liquids generated at a compressor station are complicated and expensive. In traditional station design practice, each equipment drain outlet is directly connected to a plurality of pipes with redundant drain appurtenances, all of which are piped to the appropriate facility low or high pressure main drain pipe line. As stated above, the traditional industry practice is to have instrumentation and controls for each different type of drain source along with triple redundancy via two parallel automated drain valve systems with a third manual valve bypass as a back-up. The automated drain valves are controlled by instrumentation installed to measure and control the level in the vessel sump associated with each drain outlet. Each of the redundant drain systems requires inlet and outlet isolation valves, vents and drains, an automated valve, and a strainer. The isolation valves are required for performing maintenance on the automated drain valves and the strainers are located upstream of the automated valves to keep any in-line debris from fouling the automated valves.
Drain pipes in previous designs are almost always restricted because the automated valves are known to fail open. When a valve fails open if creates a path for gas to chase the dump liquid down the pipe all the way to the site storage tanks. The high pressure gas then expands in the tank(s) and vents out the top of the storage, tanks until the malfunctioning valve is taken out of service and one of the redundant back-up drain systems is brought online. Since the storage tanks are often designed and fabricated as low pressure (atmospheric) tanks there is always a risk of overwhelming the storage tanks with high pressure gas which can cause the tank to fail. Due to this concern, traditional liquid dump connections usually install pipe restriction orifices or choke nipples to limit the amount of gas that can escape when an automated valve fails. These flow restriction devices also back up the liquid that is trying to dump resulting in slow drainage, freezing concerns, and possible station shutdowns due to high liquid levels in the equipment. Because it is inevitable that the automated valves will fail, it would be desirable to simplify the facility liquid drain systems and minimize use of level-control drain valves. It would also be desirable to decrease the number of drainage pipes running throughout the facility connecting each of the drain sources to the respective low or high pressure main drain pipe(s). A simplified approach to handling liquids at a compressor station would cut down initial costs and further minimize failures that lead to shutdowns and unplanned gas emissions. What is needed is a system that performs all the above described functions for compressor facilities that can be designed to be the proper size based on initial installation need, but that can be easily expandable when it becomes necessary.